This invention relates to the treatment of a subterranean petroleum-containing formation penetrated by a well with a treating fluid capable of dissolving materials present in or on the substrata. More particularly, this invention relates to the treatment of a well or subterranean formation to remove petroleum waxes commonly known as "paraffin deposits," which may contain asphaltene components, to increase the permeability therethrough. This invention also relates to the cleaning of industrial vessels and conduits to remove paraffin deposits therefrom.
In the course of producing certain types of petroleum oils and gases from subterranean formations penetrated by a well, paraffins and asphaltenes deposited from the oil tend to clog the pores of the reservoir rock, the well casings, and the tubings and screens through which the oil and gas flow to the surface. The deposition of paraffins may proceed to the point that production is completely interrupted.
In the past, the problem of removing paraffin deposits has been approached in various ways. The oldest method, and perhaps the most effective heretofore, was to clean the wellbore mechanically, as for example, by scraping. This method, however, was too expensive to be economically feasible as it resulted in lost production time, additional rig time, and high costs for labor and mechanical tools. Moreover, scraping could not reach deposits left behind the well casing or within the producing formation.
Another common practice to remove paraffin deposits employs chemical solvents to restore flow to a plugged formation and wellbore. Solvents customarily used to dissolve paraffins and asphaltenes include benzene derivatives, gasoline, distillates, carbon tetrachloride and carbon disulfide. Usually hot oil or solvent is injected as a liquid to dissolve the paraffins and other soluble hydrocarbons. But removal of soluble paraffins and other hydrocarbons by solvent injection poses two problems. First, the condition of the well may actually be worsened if insoluble, soil-like constituents of the sludge fouling the well remain behind after the treatment in higher concentrations than before the solvent injection was performed. Second, solvents may become excessively diluted during injection by contamination with reservoir fluids before they reach the zone of plugging since paraffins form in the lower portion of the well.
Other methods of removing paraffins from producing wells require heat generation in situ to dissolve the paraffinic components of deposits. The method used may rely upon heat generated by the exothermic neutralization reaction of alternately administered slugs of acid and base solutions. Or a hot, foamed detergent may be generated in situ by administering alternate slugs of alkali metasilicate, or similar detergents, and concentrated sulfuric acid solutions containing a foam stabilizer. The latter method is disclosed in U.S. Pat. No. 4,089,703 to White.
One of the most effective solvents for paraffins of varying compositions is carbon disulfide. But carbon disulfide is difficult and hazardous to use because it is highly toxic, flammable, and volatile. As it is also readily soluble in oil, carbon disulfide is difficult to place deep into wells containing a standing column of oil. To reduce the hazards associated with using carbon disulfide, Rowlinson in U.S. Pat. No. 3,375,192 discloses a mixture for use in cleaning oil wells comprising 8 to 16 volume percent of pentane and the balance of carbon disulfide. The pentane is used to raise the ignition temperature of the carbon disulfide and thereby reduce the fire hazard associated with its use.
U.S. Pat. No. 3,241,615 to Bertness discloses a process of removing hydrocarbon accumulation from within the wellbore by contacting the substrata with a liquid mixture comprising a surfactant and a solvent such as carbon disulfide and flushing with water to disperse the paraffins. A mixture of water with the solvent-surfactant solution is also contemplated.
Solvent emulsions have also been employed to remove paraffins from plugged wellbores and oil well tubings. In U.S. Pat. No. 2,358,665 to Shapiro, a method is described in which oil immiscible solvent emulsions having a specific gravity greater than oil sink through the oil column until, having reached the temperature at which they become unstable, they break, releasing the undiluted solvent to dissolve the waxes upon contact. This method solves the problem of getting the solvent into the lower region of the oil column without dilution, but makes release of the solvent depend upon the temperature profile in the reservoir. A method to remove dependence of the point of solvent release upon temperature in the wellbore is disclosed in U.S. Pat. No. 3,724,553 to Snavely. A thermally stable oil-in-water emulsion of a mixture of solvents for paraffins is broken to release the solvents by contacting the aqueous phase with salt injected into the well either before or after injection of the emulsion. However, this method possesses the disadvantage of potential damage to the reservoir from the addition of salts.
Foams minimize the volume of treating fluid required while simultaneously reducing the density of the treating fluid. A foaming agent and a gas are commonly added to a liquid treating fluid to form a relatively large volume of foamed treating fluid from a small amount of solvent and additives. U.S. Pat. No. 3,572,439 to Hutchinson et al. discloses a preformed well circulation foam containing water or water-cosolvent mixtures stabilized by ammoniated concentrates of organic foaming agents. Use of a mixture of foaming agents is also contemplated.
Generation and maintenance of foam is not difficult when the fluid to be contacted or displaced is either water or a variety of brines. Contact with crude oil, however, depresses many foams. On the other hand, water-free foamed solvents often form viscous water-in-oil emulsions upon contact with water. Use of a foamed solvent, therefore, may cause blocking of the formation in situ when it mixes with reservoir waters, and removal of the emulsion from the wellbore may prove difficult.
The use of oil-in-water emulsions may also be injurious to certain formations that contain clays or bentonitic shale. Introduction of foreign water into an argillaceous reservoir causes certain clays and bentonitic shales to swell due to ion exchange between non-ionically balanced injection water and the formation. Since swelling is pH sensitive, it is well known to acidify foreign waters to counteract the loss in permeability which results from such swelling. However, acidic waters, even if used in solvent emulsions, pose the disadvantage of being extremely corrosive to metal unless expensive corrosion inhibitors are added.
Certain reservoir formations containing iron-bearing minerals are also damaged by deposition of iron-bearing precipitates within the formation if a solvent-containing fluid useful for removing paraffin deposits is used in conjunction with an acidic component for dissolving carbonate or silicate deposits. Acidification of solvent-containing fluids is common since carbonates and iron-containing minerals are among the deposits most commonly dissolved from wells. However, at the wellbore pressures necessary to prevent blowouts in active reservoirs, stimulation fluids travel outwardly from the wellbore into the formation. Carbonates and iron-bearing components dissolved by the acidic components in the well-treating fluid travel outwardly from the well and tend to precipitate from solution as the travelling fluid contacts basic elements in the formation or becomes diluted with formation waters. In certain clay or sandstone formations containing iron-bearing minerals, such as chlorite, or iron carbonates, such as ferroin, ferroin dolomite, and siderite, an acid component in the treating fluid results in redeposition of iron materials at locations deeper in the reservoir which have been dissolved from plugging components near the wellbore.
Interest has long been shown in developing an economical composition for stimulating production in low pressure stripper wells blocked by paraffin deposits. Stripper wells are characterized by depleted formation pressures caused by extended production. High density treating fluids therefore create wellbore pressures sufficient to result in excessive loss of treatment fluids into the formation during treating. Moreover, sludge remaining after paraffins and asphaltenes have been dissolved can be forced deep into the formation by the higher pressure in the wellbore and result in severe plugging difficult to reach by subsequent cleaning procedures. If the treating fluid is also acidified to dissolve carbonates and silicates, iron-bearing deposits can reinforce the plug in the formation and virtually close in the reservoir.
The need has long been felt in the art for an inexpensive and effective well treating fluid useful for dissolving paraffin deposits which is neither explosive nor dependent upon the thermal gradient in the reservoir, and which will not cause salt damage to the formation by ion exchange with clays contained therein. Additionally, a composition useful for dissolving paraffin deposits from formations containing iron-bearing minerals that will not cause redeposition within the reservoir of iron containing deposits has long been sought in the art.
It is an object of this invention to provide a composition comprising a foamed oil-in-water emulsion of solvent in non-formation damaging aqueous solution which is useful for cleaning paraffin deposits from the wellbore, formation rock, or gravel pack of wells without damage to the surrounding formation.
It is a further object of this invention to provide a cost-efficient method of removing paraffin deposits in which the volume of solvent used to dissolve a given quantity of paraffin deposits is minimized and loss to the formation of the stimulation fluid is avoided.
An additional object of this invention is to provide a low density, foamed solvent emulsion which is stable while removing paraffin deposits from the wellbore and surrounding formations under agitated conditions but which breaks down spontanously under quiescent conditions to form a liquid phase easy to remove from the wellbore.
Yet another object of this invention is to provide a method for removing paraffin deposits from depleted stripper wells in which formation pressure is used to assist in cleaning the residue of dissolved deposits from the well.
It is still another object of this invention to provide a foamed solvent emulsion that maintains a stable viscosity during injection and circulation when crude oil or formation water is contacted or when asphaltenes and other natural emulsifiers are dissolved during treatment.
Additional objects, advantages and features of the invention will become apparent to those skilled in the art from the following description.